Rotary drag bits employing superabrasive cutting elements in the form of polycrystalline diamond compact (PDC) cutting elements have been employed for decades. PDC cutting elements are typically comprised of a disc-shaped diamond “table” formed under high-pressure and high-temperature conditions and bonded to a supporting substrate such as cemented tungsten carbide (WC), although other configurations are known. Bits carrying PDC cutting elements, which for example, may be brazed into pockets in the bit face, pockets in blades extending from the face, or mounted to studs inserted into the bit body, have proven very effective in achieving high rates of penetration (ROP) in drilling subterranean formations exhibiting low to medium compressive strengths. Improvements in the design of hydraulic flow regimes about the face of bits, cutter design, and drilling fluid formulation have reduced prior, notable tendencies of such bits to “ball” by increasing the volume of formation material which may be cut before exceeding the ability of the bit and its associated drilling fluid flow to clear the formation cuttings from the bit face.
Even in view of such improvements, however, PDC cutting elements still suffer from what might simply be termed “overloading” even at low weight-on-bit (WOB) applied to the drill string to which the bit carrying such cutting elements is mounted, especially if aggressive cutting structures are employed. The relationship of torque to WOB may be employed as an indicator of aggressiveness for cutting elements, so the higher the torque to WOB ratio, the more aggressive the bit. The problem of excessive bit aggressiveness is particularly significant in relatively low compressive strength formations where an unduly great depth of cut (DOC) may be achieved at extremely low WOB. The problem may also be aggravated by drill string oscillations, wherein the elasticity of the drill string may cause erratic application of WOB to the drill bit, with consequent overloading.
Another, separate problem involves drilling from a zone or stratum of relatively higher formation compressive strength to a “softer” zone of significantly lower compressive strength, which problem may also occur in so-called “interbedded” formations, wherein stringers of a harder rock, of relatively higher compressive strength, are intermittently dispersed in a softer rock, of relatively lower compressive strength. As a bit drills into the softer formation material without changing the applied WOB (or before the WOB can be reduced by the driller), the penetration of the PDC cutting elements, and thus the resulting torque on the bit (TOB), increase almost instantaneously and by a substantial magnitude. The abruptly higher torque, in turn, may cause damage to the cutting elements and/or the bit body itself. In directional drilling, such a change causes the tool face orientation of the directional (measuring-while-drilling (MWD), or a steering tool) assembly to fluctuate, making it more difficult for the directional driller to follow the planned directional path for the bit. Thus, it may be necessary for the directional driller to back off the bit from the bottom of the borehole to reset or reorient the tool face. In addition, a downhole motor, such as drilling fluid-driven Moineau-type motors commonly employed in directional drilling operations in combination with a steerable bottom-hole assembly, may completely stall under a sudden torque increase. That is, the bit may stop rotating, stopping the drilling operation and again necessitating backing off the bit from the borehole bottom to re-establish drilling fluid flow and motor output. Such interruptions in the drilling of a well can be time consuming and quite costly.
Numerous attempts using varying approaches have been made over the years to protect the integrity of diamond cutting elements and their mounting structures and to limit cutter penetration into a formation being drilled. For example, from a period even before the advent of commercial use of PDC cutting elements, U.S. Pat. No. 3,709,308 discloses the use of trailing, round natural diamonds on the bit body to limit the penetration of cubic diamonds employed to cut a formation. U.S. Pat. No. 4,351,401 discloses the use of surface set natural diamonds at or near the gage of the bit as penetration limiters to control the depth-of-cut of PDC cutting elements on the bit face. The following other patents disclose the use of a variety of structures immediately trailing PDC cutting elements (with respect to the intended direction of bit rotation) to protect the cutting elements or their mounting structures: U.S. Pat. Nos. 4,889,017; 4,991,670; 5,244,039 and 5,303,785. U.S. Pat. No. 5,314,033 discloses, inter alia, the use of cooperating positive and negative or neutral back rake cutting elements to limit penetration of the positive rake cutting elements into the formation. Another approach to limiting cutting element penetration is to employ structures or features on the bit body rotationally preceding (rather than trailing) PDC cutting elements, as disclosed in U.S. Pat. Nos. 3,153,458; 4,554,986; 5,199,511 and 5,595,252.
In another context, that of so-called “anti-whirl” drilling structures, it has been asserted in U.S. Pat. No. 5,402,856 that a bearing surface aligned with a resultant radial force generated by an anti-whirl underreamer should be sized so that force per area applied to the borehole sidewall will not exceed the compressive strength of the formation being underreamed. See also U.S. Pat. Nos. 4,982,802; 5,010,789; 5,042,596; 5,111,892 and 5,131,478.
While some of the foregoing patents recognize the desirability to limit cutter penetration, or DOC, or otherwise limit forces applied to a borehole surface, the disclosed approaches are somewhat generalized in nature and fail to accommodate or implement an engineered approach to achieving a target ROP in combination with more stable, predictable bit performance. Furthermore, the disclosed approaches do not provide a bit or method of drilling that is generally tolerant to being axially loaded with an amount of WOB over and in excess what would be optimum for the current rate-of-penetration for the particular formation being drilled and which would not generate high amounts of potentially bit-stopping or bit-damaging torque-on-bit should the bit nonetheless be subjected to such excessive amounts of weight-on-bit.
Various successful solutions to the problem of excessive cutting element penetration are presented in U.S. Pat. Nos. 6,298,930; 6,460,631; 6,779,613 and 6,935,441, the disclosure of each of which is incorporated by reference in its entirety herein. Specifically, U.S. Pat. No. 6,298,930 describes a rotary drag bit including exterior features to control the depth of cut by cutting elements mounted thereon, so as to control the volume of formation material cut per bit rotation as well as the torque experienced by the bit and an associated bottom-hole assembly. These features, also termed depth of cut control (DOCC) features, provide a non-cutting bearing surface or surfaces with sufficient surface area to withstand the axial or longitudinal WOB without exceeding the compressive strength of the formation being drilled and such that the depth of penetration of PDC cutting elements cutting into the formation is controlled. Because the DOCC features are subject to the applied WOB as well as to contact with the abrasive formation and abrasives-laden drilling fluids, the DOCC features may be layered onto the surface of a steel body bit as an appliqué or hard face weld having the material characteristics required for a high load and high abrasion/erosion environment, or include individual, discrete wear resistant elements or inserts set in bearing surfaces cast in the face of a matrix-type bit, as depicted in FIG. 1 of U.S. Pat. No. 6,298,930. The wear resistant inserts or elements may comprise tungsten carbide bricks or discs, diamond grit, diamond film, natural or synthetic diamond (PDC or TSP), or cubic boron nitride.
FIGS. 10A and 10B of the '930 patent, respectively, depict different DOCC feature and PDC cutter combinations. In each instance, a single PDC cutter is secured to a combined cutter carrier and DOC limiter, the carrier then being received within a cavity in the face (or on a blade) of a bit and secured therein. The DOC limiter includes a protrusion exhibiting a bearing surface.
While the DOCC features are extremely advantageous for limiting a depth of cut while managing a given, relatively stable WOB, a concern when an earth-boring tool moves rapidly between relatively harder and relatively softer formation materials of markedly difference compressive strengths under high WOB is so-called “stick-slip” of the drill string and bottom hole assembly, which occurs when the bit suddenly engages a formation too aggressively, increasing reactive torque to the extent that drill string rotation ceases until the reactive torque is great enough to rotate the drill string again, albeit in an uncontrolled manner. Thus, tool face orientation may be compromised. In addition to stick-slip, when an earth-boring tool moves rapidly between relatively softer and relatively harder formations under high WOB impact damage to PDC cutting elements and, in extreme cases, to the bit itself, may occur. Use of conventional DOCC features on a PDC cutting element-equipped drill bit may, typically, reduce bit aggressiveness on the order of about 20% to about 30% in comparison to the same bit without the DOCC features. As existing DOCC features rely solely upon the surface area of bearing elements to control exposure of PDC cutting elements and bit aggressiveness, such DOCC features may not be sufficiently responsive in terms of aggressiveness reduction to sudden changes in rock compressive strength to avoid stick-slip and impact damage.
The inventors herein have recognized the shortcomings of conventional DOCC techniques in certain subterranean drilling environments and have developed a counterintuitive, novel and unobvious approach to controlling bit aggressiveness that is substantially more responsive to changes in formation compressive strength, such as may occur with interbedded formations, than conventional DOCC techniques.